Multiphase metering system

ABSTRACT

A multi-phase fluid is passed through a Coriolis flowmeter and a watercut meter. The multi-phase fluid includes two phases during a first time period and three phases during a second time period. It is determined that the multi-phase fluid includes two phases during the first time period, and a first value of a parameter of the multi-phase fluid is determined using a value measured by the Coriolis flowmeter during the first time period. A second value of a parameter of the multi-phase fluid is determined using a value measured by the watercut meter during the first time period. The first value is compared to the second value, and it is determined, based on the comparison, that the first value and the second value are inconsistent with each other.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.61/376,589, filed Aug. 24, 2010 and titled MULTIPHASE METERING SYSTEM,and U.S. Provisional Application No. 61/405,944, filed Oct. 22, 2010 andtitled MULTIPHASE METERING SYSTEM. The disclosures of these priorprovisional applications are incorporated by reference in theirentirety.

TECHNICAL FIELD

This description relates to flowmeters.

BACKGROUND

Flowmeters provide information about materials being transferred througha conduit. For example, mass flowmeters provide a measurement of themass of material being transferred through a conduit. Similarly, densityflowmeters, or densitometers, provide a measurement of the density ofmaterial flowing through a conduit. Mass flowmeters also may provide ameasurement of the density of the material.

For example, Coriolis-type mass flowmeters are based on the Corioliseffect, in which material flowing through a rotating conduit is affectedby a Coriolis force and therefore experiences an acceleration. ManyCoriolis-type mass flowmeters induce a Coriolis force by sinusoidallyoscillating a conduit about a pivot axis orthogonal to the length of theconduit. In such mass flowmeters, the Coriolis reaction forceexperienced by the traveling fluid mass is transferred to the conduititself and is manifested as a deflection or offset of the conduit in thedirection of the Coriolis force vector in the plane of rotation.

SUMMARY

In one general aspect, a method includes passing a multi-phase fluidthrough a Coriolis flowmeter, the multi-phase fluid including two phasesduring a first time period and three phases during a second time period,passing the multi-phase fluid through a watercut meter, determining thatthe multi-phase fluid includes two phases during the first time period,determining a first value of a parameter of the multi-phase fluid usinga value measured by the Coriolis flowmeter during the first time period,determining a second value of a parameter of the multi-phase fluid usinga value measured by the watercut meter during the first time period,comparing the first value to the second value, and determining, based onthe comparison, that the first value and the second value areinconsistent with each other.

Implementations may include one or more of the following features. Theparameter may be a density of the multi-phase fluid, and the first valueis a first density value and the second value is a second density value.The second density may be determined using

${\rho_{mW} = {{\frac{\delta_{wW}}{100}*\rho_{w}} + {\left( {1 - \frac{\delta_{wW}}{100}} \right)*\rho_{o}}}},$

where ρ_(o) is an assumed oil density, ρ_(w) is an assumed waterdensity,

$\delta_{wC} = {\frac{\left( {\rho_{m} - \rho_{o}} \right)}{\left( {\rho_{w} - \rho_{o}} \right)} \times 100\%}$

is an estimate of the watercut, and ρ_(m) is the first density of themulti-phase fluid measured by the Coriolis flowmeter. The parameter maybe a water cut of the multi-phase fluid, and the first value is a watercut measured by the water cut meter, and the second value is a water cutdetermined using values read from the Coriolis flowmeter.

Comparing the first density value to the second density value mayinclude determining a percentage difference between the first densityvalue and the second density value. In some implementations, it may bedetermined that an error exists in the watercut meter based on theinconsistency, or it may be determined that an error exists in theCoriolis flowmeter based on the inconsistency. At least one of theassumed oil density or the assumed water density may be determined to beinaccurate based on the inconsistency. During the first time period, themulti-phase fluid may be purely liquid. Determining, based on thecomparison, that the first value and the second value are inconsistentwith each other may include determining that a percentage differencebetween the first value and the second value exceeds a threshold. Thethreshold may be about 5%.

In another general aspect, a system includes a watercut meter configuredto receive a fluid, and a Coriolis flowmeter coupled to the watercutmeter. The Coriolis flowmeter is configured to receive the fluid, andthe flowmeter is oriented such that the fluid flows downward through theCoriolis flowmeter.

Implementations may include one or more of the following features. Thesystem also may include a computing device configured to determine thatthe multi-phase fluid includes two phases during the first time period,determine a first value of a parameter of the multi-phase fluid using avalue measured by the Coriolis flowmeter during the first time period,determine a second value of a parameter of the multi-phase fluid using avalue measured by the watercut meter during the first time period,compare the first value to the second value, and determine, based on thecomparison, that the first value and the second value are inconsistentwith each other. The computing device may be a processor included in atransmitter coupled to the Coriolis flowmeter. The computing device maybe a processor included in a flow computer external to the Coriolisflowmeter and the water cut meter.

In some implementations, the parameter may include density of themulti-phase fluid, and the first value is a first density value and thesecond value is a second density value. The second density may bedetermined using

${\rho_{mW} = {{\frac{\delta_{wW}}{100}*\rho_{w}} + {\left( {1 - \frac{\delta_{wW}}{100}} \right)*\rho_{o}}}},$

where ρ_(o) is an assumed oil density, ρ_(w) is an assumed waterdensity,

$\delta_{wC} = {\frac{\left( {\rho_{m} - \rho_{o}} \right)}{\left( {\rho_{w} - \rho_{o}} \right)} \times 100\%}$

is an estimate of the watercut, and ρ_(m) is the first density of themulti-phase fluid measured by the Coriolis flowmeter. The parameter mayinclude a water cut of the multi-phase fluid, and the first value is awater cut measured by the water cut meter, and the second value is awater cut determined using values read from the Coriolis flowmeter.

To compare the first density value to the second density value, thecomputing device may be configured to determine a percentage differencebetween the first density value and the second density value. In someimplementations, it may be determined, based on the inconsistency, thatan error exists in the watercut meter. The computing device may befurther configured to determine, based on the inconsistency, that anerror exists in the Coriolis flowmeter. The computing device may befurther configured to determine, based on the inconsistency, that atleast one of the assumed oil density or the assumed water density isinaccurate. To determine, based on the comparison, that the first valueand the second value are inconsistent with each other, the computingdevice may be configured to determine that a percentage differencebetween the first value and the second value exceeds a threshold. Thethreshold may be about 5%. The multi-phase fluid during the first timeperiod may be purely liquid. The water cut meter may be a liquidfraction probe.

Implementations of any of the techniques described above may include amethod or process, a system, a flowmeter, or instructions stored on astorage device of a flow meter transmitter. Details of particularimplementations are set forth in the accompanying drawings anddescription below. Other features will be apparent from the followingdescription, including the drawings, and the claims.

DESCRIPTION OF DRAWINGS

FIG. 1A is an illustration of a Coriolis flowmeter using a bentflowtube.

FIG. 1B is an illustration of a Coriolis flowmeter using a straightflowtube.

FIG. 2 is a block diagram of a Coriolis flowmeter.

FIG. 3 is a flowchart illustrating an operation of the Coriolisflowmeter of FIG. 2.

FIG. 4 is a flowchart illustrating techniques for determining liquid andgas flow rates for a two-phase flow.

FIG. 5A is a block diagram of a Coriolis flowmeter.

FIG. 5B is a diagram of an implementation of the system of FIG. 5A.

FIG. 6 is an illustration of another implementation of the system ofFIG. 5A.

FIGS. 7 and 8 show example processes for determining whether aninconsistency exists between a Coriolis flowmeter and a water cut meter.

DETAILED DESCRIPTION

Types of flowmeters include digital flowmeters. For example, U.S. Pat.No. 6,311,136, which is hereby incorporated by reference, discloses theuse of a digital flowmeter and related technology including signalprocessing and measurement techniques. Such digital flowmeters may bevery precise in their measurements, with little or negligible noise, andmay be capable of enabling a wide range of positive and negative gainsat the driver circuitry for driving the conduit. Such digital flowmetersare thus advantageous in a variety of settings. For example,commonly-assigned U.S. Pat. No. 6,505,519, which is incorporated byreference, discloses the use of a wide gain range, and/or the use ofnegative gain, to prevent stalling and to more accurately exercisecontrol of the flowtube, even during difficult conditions such astwo-phase flow (e.g., a flow containing a mixture of liquid and gas).

Although digital flowmeters are specifically discussed below withrespect to, for example, FIGS. 1 and 2, it should be understood thatanalog flowmeters also exist. Although such analog flowmeters may beprone to typical shortcomings of analog circuitry, e.g., low precisionand high noise measurements relative to digital flowmeters, they alsomay be compatible with the various techniques and implementationsdiscussed herein. Thus, in the following discussion, the term“flowmeter” or “meter” is used to refer to any type of device and/orsystem in which a Coriolis flowmeter system uses various control systemsand related elements to measure a mass flow, density, and/or otherparameters of a material(s) moving through a flowtube or other conduit.

FIG. 1A is an illustration of a digital flowmeter using a bent flowtube102. Specifically, the bent flowtube 102 may be used to measure one ormore physical characteristics of, for example, a (traveling) fluid, asreferred to above. In FIG. 1A, a digital transmitter 104 exchangessensor and drive signals with the bent flowtube 102, so as to both sensean oscillation of the bent flowtube 102, and to drive the oscillation ofthe bent flowtube 102 accordingly. By quickly and accurately determiningthe sensor and drive signals, the digital transmitter 104, as referredto above, provides for fast and accurate operation of the bent flowtube102. Examples of the digital transmitter 104 being used with a bentflowtube are provided in, for example, commonly-assigned U.S. Pat. No.6,311,136.

FIG. 1B is an illustration of a digital flowmeter using a straightflowtube 106. More specifically, in FIG. 1B, the straight flowtube 106interacts with the digital transmitter 104. Such a straight flowtubeoperates similarly to the bent flowtube 102 on a conceptual level, andhas various advantages/disadvantages relative to the bent flowtube 102.For example, the straight flowtube 106 may be easier to (completely)fill and empty than the bent flowtube 102, simply due to the geometry ofits construction. In operation, the bent flowtube 102 may operate at afrequency of, for example, 50-110 Hz, while the straight flowtube 106may operate at a frequency of, for example, 300-1,000 Hz. The bentflowtube 102 represents flowtubes having a variety of diameters, and maybe operated in multiple orientations, such as, for example, in avertical or horizontal orientation.

Referring to FIG. 2, a digital mass flowmeter 200 includes the digitaltransmitter 104, one or more motion sensors 205, one or more drivers210, a flowtube 215 (which also may be referred to as a conduit, andwhich may represent either the bent flowtube 102, the straight flowtube106, or some other type of flowtube), and a temperature sensor 220. Thedigital transmitter 104 may be implemented using one or more of, forexample, a processor, a Digital Signal Processor (DSP), afield-programmable gate array (FPGA), an ASIC, other programmable logicor gate arrays, or programmable logic with a processor core. It shouldbe understood that, as described in U.S. Pat. No. 6,311,136, associateddigital-to-analog converters may be included for operation of thedrivers 210, while analog-to-digital converters may be used to convertsensor signals from the sensors 205 for use by the digital transmitter104.

The digital transmitter 104 generates a measurement of, for example,density and/or mass flow of a material flowing through the flowtube 215,based at least on signals received from the motion sensors 205. Thedigital transmitter 104 also controls the drivers 210 to induce motionin the flowtube 215. This motion is sensed by the motion sensors 205.

Density measurements of the material flowing through the flowtube arerelated to, for example, the frequency of the motion of the flowtube 215that is induced in the flowtube 215 by a driving force supplied by thedrivers 210, and/or to the temperature of the flowtube 215. Similarly,mass flow through the flowtube 215 is related to the phase and frequencyof the motion of the flowtube 215, as well as to the temperature of theflowtube 215.

The temperature in the flowtube 215, which is measured using thetemperature sensor 220, affects certain properties of the flowtube, suchas its stiffness and dimensions. The digital transmitter 104 maycompensate for these temperature effects. Also in FIG. 2, a pressuresensor 225 is in communication with the transmitter 104, and isconnected to the flowtube 215 so as to be operable to sense a pressureof a material flowing through the flowtube 215.

It should be understood that both the pressure of the fluid entering theflowtube 215 and the pressure drop across relevant points on theflowtube may be indicators of certain flow conditions. Also, whileexternal temperature sensors may be used to measure the fluidtemperature, such sensors may be used in addition to an internalflowmeter sensor designed to measure a representative temperature forflowtube calibrations. Also, some flowtubes use multiple temperaturesensors for the purpose of correcting measurements for an effect ofdifferential temperature between the process fluid and the environment(e.g., a case temperature of a housing of the flowtube). As discussed inmore detail below, one potential use for the inlet fluid temperature andpressure measurements is to calculate the actual densities of a liquidand gas in a two-phase flow, based on predefined formulae.

A liquid fraction probe 230 refers to a device for measuring a volumefraction of liquid, e.g., water, when a liquid in the flowtube 215includes water and another fluid, such as oil. Of course, such a probe,or similar probes, may be used to measure the volume fraction of a fluidother than water, if such a measurement is preferred or if the liquiddoes not include water. In the below description, a measured liquid isgenerally assumed to be water for the purposes of example, so that theliquid fraction probe 230 is generally referred to as a water fractionprobe 230, or a water-cut probe 230.

A void fraction sensor 235 measures a percentage of a material in theflowtube 215 that is in gaseous form. For example, water flowing throughthe flowtube 215 may contain air, perhaps in the form of bubbles. Such acondition, in which the material flowing through the flowtube 215contains more than one material is generally referred to as “two-phaseflow.” In particular, the term “two-phase flow” may refer to a liquidand a gas; however, “two-phase flow” also may refer to othercombinations of materials, such as two liquids (e.g., oil and water).

Various techniques, represented generally in FIG. 2 by the void fractionsensor 235, exist for measuring the gas void fraction in a two-phaseflow of liquid and gas (where the gas void fraction may be considered asthe proportion of gas by volume in the mixture, for example expressed asa percentage). For example, various sensors or probes exist that may beinserted into the flow to determine a gas void fraction. As anotherexample, a venturi tube (i.e., a tube with a constricted throat thatdetermines fluid pressures and velocities by measurement of differentialpressures generated at the throat as a fluid traverses the tube),relying on the fact that gas generally moves with a higher velocity thanliquid(s) through a restriction, may be used to determine a pressuregradient and thereby allow a determination of the gas void fraction.

Measurements of gas void fractions also may be obtained using equipmentthat is wholly external to the flowtube. For example, sonar measurementsmay be taken to determine gas void fraction. As a specific example ofsuch a sonar-based system, the SONARtrac™ gas void fraction monitoringsystem produced by CiDRA Corporation of Wallingford, Conn. may be used.

In this description, an amount of gas in a flowing fluid, measured bythe void fraction sensor or otherwise determined, may be referred to asvoid fraction or α, and is defined as α=volume of gas/totalvolume=volume of gas/(volume of liquid+volume of gas). Accordingly, aquantity referred to herein as the liquid fraction is defined as 1-α.

In many applications where mass flow measurements are required, the voidfraction of the flow can be as high as 20, 30, 40% or more. However,even at very small void fractions of 0.5%, the fundamental theory behindthe Coriolis flowmeter becomes less applicable.

Moreover, a presence of gas in the fluid flow also may affect both anactual and a measured value of a density of the fluid flow, generallycausing the density measurement to be, and to read, lower than if thefluid flow contained only the liquid component. That is, it should beunderstood that a density ρ_(liquid) of a liquid flowing by itselfthrough a flowtube will be higher than an actual density ρ_(true) of atwo-phase flow containing the liquid and a gas, since a density of thegas (e.g., air) will generally be lower than a density of the liquid(e.g., water) in the two-phase flow. In other words, there is a densityreduction when gas is added to a liquid flow that previously containedonly the liquid.

Beyond this physical phenomenon, a Coriolis flowmeter measuring atwo-phase fluid flow containing gas may output a density readingρ_(apparent) that is an ostensible measurement of the bulk density ofthe two-phase flow (e.g., of the water and air combined). This rawmeasurement ρ_(apparent) will generally be different (lower) than theactual bulk density ρ_(true) of the two-phase flow. For example, theresonant frequency used by the flowmeter may be correct for a situationin which only the liquid component is present, but, due to relativemotion of the gas in the fluid flow, which serves to mask an inertia ofthe flowtube (i.e., causes an amount of inertia to be less than would beexpected for a liquid-only flow), the density measurement may read low.

It should be understood that many conventional prior art flowmeters wereunconcerned with this problem, since most such Coriolis flowmeters failto continue operating (e.g. stall or output inaccurate measurements) ateven the slightest amounts of void fraction.

U.S. Pat. No. 6,505,519, which is incorporated by reference above,discloses that such a variation of ρ_(apparent) (i.e., an indicated bulkdensity reading of a two-phase flow that is output by a Coriolisflowmeter) from ρ_(true) (i.e., an actual bulk density of the two-phaseflow) may be characterized by a variety of techniques. As a result, ameasured ρ_(apparent) may be corrected to obtain an actual bulk densityρ_(corrected), which is, at least approximately, equal to ρ_(true).

Somewhat similarly, an indicated bulk mass flow rate MF_(apparent)(i.e., a mass flow rate of the entire two-phase flow) measured by aCoriolis flowmeter may be different by a predictable or characterizableamount from an actual bulk mass flow rate MF_(true). It should beunderstood that correction techniques for corrected bulk mass flow rateMF_(true) may be different than the techniques for correcting fordensity. For example, various techniques for correcting a measuredMF_(apparent) to obtain an actual MF_(true) (or, at least,MF_(corrected)) are discussed in U.S. Pat. No. 6,505,519.

Examples of detailed techniques for correcting ρ_(apparent) andMF_(apparent) are discussed in more detail below and are also discussedin U.S. Pat. Nos. 7,059,199; 7,188,534; and 7,188,534, all of which arehereby incorporated by reference. Generally speaking, though, withrespect to FIG. 2, the digital transmitter is shown as including adensity correction system 240, which has access to a density correctiondatabase 245, and a mass flow rate correction system 250, which hasaccess to a mass flow correction database 255. As discussed in moredetail below, the databases 245 and 255 may contain, for example,correction algorithms that have been derived theoretically or obtainedempirically, and/or correction tables that provide corrected density ormass flow values for a given set of input parameters. The databases 245and 255 also may store a variety of other types of information that maybe useful in performing the density or mass flow corrections. Forexample, the density correction database may store a number of densitiesρ_(liquid) corresponding to particular liquids (e.g., water or oil).

Further in FIG. 2, a void fraction determination/correction system 260is operable to determine a void fraction of a two-phase flow including aliquid and a gas. In one implementation, for example, the void fractiondetermination/correction system 260 may determine an actual voidfraction α_(true) from the corrected density ρ_(corrected). In anotherimplementation, the void fraction determination/correction system 260may input an apparent or indicated void fraction measurement obtained bythe void fraction sensor 235, and may correct this measurement based onan error characterization similar to the density and mass flowtechniques referred to above. In another implementation, the voidfraction sensor 235 may be operable to directly measure an actual voidfraction α_(true), in which case the void fractiondetermination/correction system 260 simply inputs this measurement.

Once the factors of ρ_(corrected), MF_(corrected), and a α_(corrected)have been determined, and perhaps in conjunction with other known ordiscoverable quantities, a flow component mass flow rate determinationsystem 265 may operate to simultaneously determine a mass flow rate forthe liquid phase component and a mass flow rate for the gas phasecomponent. That is, the transmitter 104 is operable to determineindividual flowrates MF_(liquid) and MF_(gas) of the flow components, asopposed to merely determining the bulk flowrate of the combined or totaltwo-phase flow MF_(true). Although, as just referred to, suchmeasurements may be determined and/or output simultaneously, they alsomay be determined separately or independently of one another. Once thecomponent flow rates MF_(liquid) and MF_(gas) have been determined inthe manner generally outlined above, these initial determinations may beimproved upon by a process that relies on superficial velocities of theflow components, slip velocities between the components, and/or anidentified flow regime of the flow. In this way, improved values forflow rates MF_(liquid) and MF_(gas) may be obtained, or may be obtainedover time as those flow rates change.

Superficial velocities are referred to herein as those velocities thatwould exist if the same mass flow rate of a given phase was traveling asa single phase through the flowtube 215. A superficial velocitydetermination/correction system 270 is included in the transmitter 104for, for example, determining an apparent or corrected superficialvelocity of a gas or liquid in the two-phase flow. Slip velocities referto a condition in which gas and liquid phases in a two-phase flow havedifferent average velocities. That is, an average velocity of a gasAV_(gas) is different from an average velocity of a liquid AV_(liquid).As such, a phase slip S may be defined as S=AV_(gas)/AV_(liquid).

A flow regime is a term that refers to a characterization of the mannerin which the two phases flow through the flowtube 215 with respect toone another and/or the flowtube 215, and may be expressed, at leastpartially, in terms of the superficial velocities just determined. Forexample, one flow regime is known as the “bubble regime,” in which gasis entrained as bubbles within a liquid. As another example, the “slugregime” refers to a series of liquid “plugs” or “slugs” separated byrelatively large gas pockets. For example, in vertical flow, the gas ina slug flow regime may occupy almost an entire cross-sectional area ofthe flowtube 215, so that the resulting flow alternates betweenhigh-liquid and high-gas composition. Other flow regimes are known toexist and to have certain defined characteristics, including, forexample, the annular flow regime, the dispersed flow regime, and frothflow regime, and others.

The existence of a particular flow regime is known to be influenced by avariety of factors, including, for example, a gas void fraction in thefluid flow, an orientation of the flowtube 215 (e.g., vertical orhorizontal), a diameter of the flowtube 215, the materials includedwithin the two-phase flow, and the velocities (and relative velocities)of the materials within the two phase flow. Depending on these and otherfactors, a particular fluid flow may transition between several flowregimes over a given period of time.

Information about phase slip may be determined at least in part fromflow regime knowledge. For example, in the bubble flow regime, assumingthe bubbles are uniformly distributed, there may be little relativemotion between the phases. Where the bubbles congregate and combine toform a less uniform distribution of the gas phase, some slippage mayoccur between the phases, with the gas tending to cut through the liquidphase.

In FIG. 2, a flow regime determination system 275 is included that hasaccess to a database 280 of flow regime maps. In this way, informationabout an existing flow regime, including phase slip information, may beobtained, stored, and accessed for use in simultaneously determiningliquid and gas mass flow rates within a two-phase flow.

In FIG. 2, it should be understood that the various components of thedigital transmitter 104 are in communication with one another, althoughcommunication links are not explicitly illustrated, for the sake ofclarity. Further, it should be understood that conventional componentsof the digital transmitter 104 are not illustrated in FIG. 2, but areassumed to exist within, or be accessible to, the digital transmitter104. For example, the digital transmitter 104 will typically include(bulk) density and mass flow rate measurement systems, as well as drivecircuitry for driving the driver 210.

FIG. 3 is a flowchart 300 illustrating an operation of the Coriolisflowmeter 200 of FIG. 2. Specifically, FIG. 3 illustrates techniques bywhich the flowmeter 200 of FIG. 2 is operable to simultaneouslydetermine liquid and gas flow rates MF_(liquid) and MF_(gas) for atwo-phase flow.

In FIG. 3, it is determined that a gas/liquid two-phase flow exists inthe flowtube 215 (302).This can be done, for example, by an operator during configuration ofthe mass flowmeter/densitometer for gas/liquid flow. As another example,this determination may be made automatically by using a feature of theCoriolis flowmeter to detect that a condition of two-phase gas-liquidflow exists. In the latter case, such techniques are described ingreater detail in, for example, U.S. Pat. No. 6,311,136 and U.S. Pat.No. 6,505,519, incorporated by reference above.

Once the existence of two-phase flow is established, a corrected bulkdensity ρ_(corrected) is established (304) by the density correctionsystem 240, using the density correction database 245 of the transmitter104. That is, an indicated density ρ_(apparent) is corrected to obtainρ_(corrected). Techniques for performing this correction are discussedin more detail below.

Once ρ_(corrected) is determined, a corrected gas void fractionα_(corrected) may be determined (306) by the void fractiondetermination/correction system 260. Also, a corrected bulk mass flowrate MF_(corrected) is determined (308) by the mass flow rate correctionsystem 250. As with density, techniques for obtaining the corrected voidfraction α_(true) and mass flow rate MF_(corrected) are discussed inmore detail below.

In FIG. 3, it should be understood from the flowchart 300 that thedeterminations of ρ_(corrected), α_(corrected), and MF_(corrected) mayoccur in a number of sequences. For example, in one implementation, thecorrected void fraction α_(corrected) is determined based onpreviously-calculated corrected density ρ_(corrected), whereupon thecorrected mass flow rate MF_(corrected) is determined based onα_(corrected). In another implementation, α_(corrected) andρ_(corrected) may be calculated independently of one another, and/orρ_(corrected) and MF_(corrected) may be calculated independently of oneanother.

Once corrected density ρ_(corrected), corrected void fractionα_(corrected), and corrected mass flow rate MR_(corrected) are known,then the mass flow rates of the gas and liquid components are determined(310) by the flow component mass flow rate determination system 265.Techniques for determining the liquid/gas component flow rates arediscussed in more detail below with respect to FIG. 4.

Once determined, the liquid/gas component flow rates may be output ordisplayed (312) for use by an operator of the flowmeter. In this way,the operator is provided, perhaps simultaneously, with information aboutboth the liquid mass flow rate MF_(liquid) and the gas mass flow rateMF_(gas) of a two-phase flow.

In some instances, this determination may be sufficient (314), in whichcase the outputting of the liquid/gas component flow rates completes theprocess flow. However, in other implementations, the determination ofthe individual component mass flow rates may be improved upon byfactoring in information about, for example, the superficial velocitiesof the gas/liquid components, the flow regime(s) of the flow, and phaseslip, if any, between the components.

In particular, superficial velocities of the gas and liquid, SV_(gas)and SV_(liquid) are determined as follows. Gas superficial velocitySV_(gas) is defined as:

SV_(gas)=MF_(gas)/(ρ_(gas) *A _(T))  Eq. 1

where the quantity A_(T) represents a cross-section area of the flowtube215, which may be taken at a point where a void fraction of the flow ismeasured. Similarly, a liquid superficial velocity SV_(liquid) isdefined as:

SV_(liquid)=MF_(liquid)/(ρ_(liquid) *A _(T))  Eq. 2

As shown in Eqs. 1 and 2, determination of superficial velocities inthis context relies on the earlier determination of MF_(gas) andMF_(liquid). It should be understood from the above description and fromFIG. 3 that MF_(gas) and MF_(liquid) represent corrected or true massflow rates, MF_(gas) ^(corrected) and MF_(liquid) ^(corrected) sincethese factors are calculated based on ρ_(true), α_(true), and MF_(true).As a result, the superficial velocities SV_(gas) and SV_(liquid)represent corrected values SV_(gas) ^(connected) and SV_(liquid)^(corrected). Further, the density values ρ_(gas) and ρ_(liquid) refer,as above, to known densities of the liquid and gas in question, whichmay be stored in the density correction database 245. As discussed inmore detail below with respect to techniques for calculating correcteddensity ρ_(corrected), the density values ρ_(gas) and ρ_(liquid) may beknown as a function of existing temperature or pressure, as detected bytemperature sensor 220 and pressure sensor 225.

Using the superficial velocities and other known or calculated factors,some of which may be stored in the flow regime maps database 280, arelevant flow regime and/or phase slip may be determined (318) by theflow regime determination/correction system 275. Once superficialvelocities, flow regime, and phase slip are known, further correctionsmay be made to the corrected bulk density ρ_(true), corrected bulk massflow rate MF_(corrected), and/or corrected void fraction α_(corrected).In this way, as illustrated in FIG. 3, component flow rates MF_(gas) andMF_(liquid) may be determined.

Flow regime(s) in two phase liquid/gas flow may be described by contourson a graph plotting the liquid superficial velocity versus the gassuperficial velocity. As just described, an improvement todeterminations of ρ_(corrected), α_(corrected), and/or MF_(corrected)may be obtained by first establishing an approximate value of the liquidand gas flow rates, and then applying a more detailed model for the flowregime identified. For example, at relatively low GVF and relativelyhigh flow there exists a flow regime in which the aerated fluid behavesas a homogenous fluid with little or no errors in both density and massflow. This can be detected as homogenous flow requiring no correction,simply using observation of the drive gain, which shows little or noincrease in such a setting, despite a significant drop in observeddensity.

FIG. 4 is a flowchart 400 illustrating techniques for determining liquidand gas flow rates MF_(liquid) and MF_(gas) for a two-phase flow. Thatis, the flowchart 400 generally represents one example of techniques fordetermining liquid and gas flow rates (310), as described above withrespect to FIG. 3.

In FIG. 4, the determination of liquid and gas flow rates (310) beginswith inputting the corrected density, void fraction, and mass flow ratefactors ρ_(corrected), α_(corrected), and MF_(corrected) (402). In afirst instance, (404), the liquid and gas flow rates are determined(406) using Eqs. 3 and 4:

MF_(gas)=α_(corrected)(ρ_(gas)/ρ_(true))(MF_(corrected))  Eq. 3

MF_(liquid)=(1−α_(corrected))(ρ_(liquid)/(ρ_(corrected))(MF_(corrected))  Eq.4

Eqs. 3 and 4 assume that there is no slip velocity (i.e., phase slip)between the liquid and gas phases (i.e., average velocity of the gasphase, AV_(gas), and average velocity of the liquid phase, AV_(liquid),are equal). This assumption is consistent with the fact that, in thefirst instance, superficial velocities and flow regimes (and therefore,phase slip) have not been determined. In the second instance andthereafter (404), a determination is made, perhaps by the flow regimedetermination/correction system 275, as to whether phase slip exists(408). If not, then Eqs. 3 and 4 are used again (406) or the processends.

If phase slip does exist (408), defined above as S=AV_(gas)/AV_(liquid),the terms MF_(gas) and MF_(liquid) are calculated using thecross-sectional area of the flowtube 215, A_(T), as also used in thecalculation of superficial velocities in Eqs. 1 and 2 (410). Using thedefinition of slip S just given,

MF_(gas)=ρ_(gas)(α_(corrected) A _(T))(AV_(gas))=ρ_(gas)(α_(corrected) A_(T))(S)(AV_(liquid))  Eq. 5

MF_(liquid)=ρ_(liquid)((1−α_(corrected))A _(T))(AV_(liquid))  Eq. 6

Since MF_(corrected)=MF_(gas)+MF_(liquid), Eqs. 5 and 6 may be solvedfor AV_(liquid) to obtain Eq. 7:

AV_(liquid)−MF_(true)/(A_(T)(ρ_(gas)α_(corrected)+ρ_(liquid)(1−α_(corrected))))  Eq. 7

As a result, the liquid and gas flow rates are determined (406) usingEqs. 8 and 9:

MF_(liquid)=[ρ_(liquid)(1−α_(corrected))/(ρ_(gas)α_(corrected)+ρ_(liquid)(1−α_(corrected)))][MF_(corrected)]  Eq.8

MF_(gas)=MF_(corrected)−MF_(liquid)  Eq. 9

As described above, gas entrained in liquid forms a two-phase flow.Measurements of such a two-phase flow with a Coriolis flowmeter resultin indicated parameters ρ_(apparent), α_(apparent), and MF_(apparent)for density, void fraction, and mass flow rate, respectively, of thetwo-phase flow. Due to the nature of the two-phase flow in relation toan operation of the Coriolis flowmeter, these indicated values areincorrect by a predictable factor. As a result, the indicated parametersmay be corrected to obtain actual parameters ρ_(corrected),α_(corrected), and MF_(corrected). In turn, the actual, corrected valuesmay be used to simultaneously determine individual flow rates of the two(gas and liquid) components.

The above discussion provides examples of measuring component mass flowrates in a two-phase flow. Flowmeters also may be used to measurefurther mixed flows. For example, a “three-phase” flow or “mixedtwo-phase flow” refers to a situation in which two types of liquid aremixed with a gas. For example, a flowing mixture of oil and water maycontain air (or another gas), thus forming a “three-phase flow,” wherethe terminology refers to the three components of the flow, and does notgenerally imply that a solid material is included in the flow. However,in some examples, a multi-phase fluid may include a solid material, suchas sand.

FIG. 5A is a block diagram of a flowmeter system 500. The flowmetersystem 500 may be used, for example, to determine individual componentflow rates within a three-phase flow. For example, the system 500 may beused to determine a mass flow rate of a gas component and a mass flowrate of a liquid component (e.g., a component of the three-phase flowthat includes oil and water) of the three-phase flow. Additionally, thesystem 500 may be used to determine an amount of oil or a portion of oilwithin an oil, water, and gas flow that travels through a pipe at an oilextraction facility during a given period of time.

The flowmeter system 500 also may be used to obtain accuratemeasurements from the digital transmitter 104, such as, for example,density measurements or mass flow rate measurements. The system 500 alsomay be used, for example, to obtain an improved measurement from anexternal sensor, such as, for example, the liquid fraction probe 230, orthe void fraction sensor 235, relative to what measurements might beobtained using the external sensor(s) alone.

In FIG. 5A, the digital transmitter 104 includes a void fractiondetermination system 502, a density determination system 504, and a massflow rate determination system 506 (in addition to a number ofcomponents that are not shown for clarity's sake, e.g., a drive signalgenerator, or a multi-phase detection system, or any of the componentsillustrated or discussed with respect to FIG. 2). That is, as should beunderstood from the above description, the systems 502, 504, and 506 maybe used to measure corresponding parameters of a fluid flow within theflow 210. Further, as also explained above, to the extent that the fluidflow contains gas and/or mixed liquids, the measurements output by thesystems 502, 504, and 506 generally represent raw or apparent values forthe corresponding parameters, which ultimately may be corrected with acorrections system 508.

For example, an apparent mass flow rate of a three-phase fluid flowwithin the flowtube 215 may be output to the corrections system 508 forcorrection using a mass flow rate correction module 512, while anapparent density of the three-phase fluid flow within the flowtube 215may be output to the corrections system 508 for correction using adensity correction module 518. Somewhat similarly, a measurement ordetermination of an apparent void fraction within the fluid flow may becorrected using a density correction module 514, while a measurement ordetermination of an apparent liquid fraction (e.g., water cut from probe230) may be corrected using a water cut correction module 516. Asdescribed in more detail below, the various correction modules 512-518may work in conjunction with one another, and/or with other components,in order to obtain their respective corrected values.

Once obtained, corrected values such as mass flow rate, density, watercut, or void fraction (or some combination thereof) may be output to ahost computer 510 for determination of individual mass flow rates ofeach of the three components of the three-phase fluid flow, using acomponent flow rate determination system 520. As a result, and asreferenced above, individual flow rates and/or amounts of each of thethree components may be determined.

More generally, an example of the system 500 includes three generalelements used to obtain corrected measurement values and/or individualcomponent flow rates: the transmitter 104, one or more of the individualexternal sensors identified generically with a reference numeral 522,and one or more elements of the corrections system 508. Of course, manycombinations, variations, and implementations of these elements may beused, various examples of which are discussed in more detail below.

For example, in some implementations, the digital transmitter 104 maynot include the void fraction determination system 502. In some cases,the void fraction determination system 502 may be included with, orassociated with, the liquid fraction probe 230, or may be unneededdepending on a type or configuration of the void fraction sensor 235. Insuch cases, to the extent that it is needed, the void fraction may bedetermined from outputs of the correction modules 512, 516, and/or 518.

Further, although the external sensors 522 are shown in FIG. 5A to be incommunication with the digital transmitter 104 and the flowtube 215, itshould be understood that the external sensors 522 may obtain theirrespective measurements in a number of different ways. For example,examples of the temperature sensor 220, the pressure sensor 225, and thevoid fraction sensor 230 are described above, with respect to, forexample, FIG. 2. Further, the liquid fraction probe 235 may be in serieswith the flowtube 215 with respect to a primary pipe for transportingthe three-phase fluid flow, and may maintain separate communication withthe transmitter 104, the corrections system 508, and/or the hostcomputer 510.

In FIG. 5A, the corrections system 508 is shown as being separate fromthe digital transmitter 104 and the host computer 510. In someimplementations, however, the corrections system 508 may be locatedwithin the digital transmitter 104, the host computer 510, or may beassociated with one or more of the external sensors 522. In still otherimplementations, portions of the corrections system 508 may be includedwithin different sections of the system 500. For example, density andmass flow rate corrections may be performed at the digital transmitter104, while water cut corrections may be performed at the liquid fractionprobe 230.

In some implementations, the corrections system 508 may include all ofthe modules 512-518 (as shown), or some subset thereof, or may includeother modules, not specifically illustrated in FIG. 5A (e.g., acorrections module for correcting a density of the two-liquid componentwithin the three-phase flow, such as the oil/water mixture in anoil/water/gas fluid flow).

Further, some or all of any such correction modules may be integratedwith one another. For example, the mass flow rate and densitycorrections may be incorporated into one module, while the water cutcorrection module 516 may be separate.

Along the same lines, it should be understood that the component flowrate determination system 520 may be situated in a number of placeswithin the system 500. For example, the component flow ratedetermination system 520 may be located within the corrections system508, or may be located within the digital transmitter 104.

Various examples of the above and other implementations, as well asexamples of specific techniques for obtaining corrected flowmeasurements and individual component flow rates, are described in moredetail below. In general, however, it should be understood that thesystem 500 and other implementations thereof allows for all orsubstantially all of the three-phase fluid flow to flow continuouslythrough the flowtube 215 and through an associated pipe or other conduitfor transporting the three-phase flow material.

As a result, determinations of individual component flow rates do notrequire separation of the three-phase fluid flow into separate flowscontaining one or more of the constituent components. For example, whenthe three-phase flow contains oil, water, and gas, it is not necessaryto separate the gas from the oil/water liquid combination in order toperform measurements (e.g., mass flow rate) on the oil portion of theresulting oil/liquid flow. Accordingly, reliable measurements of anamount of oil produced, for example, at an oil production facility, maybe made easily, quickly, inexpensively, and reliably.

FIG. 5B is a diagram of an implementation of the system 500 of FIG. 5A.In FIG. 5B, the liquid fraction probe 230 is illustrated as a water cutprobe that is in series with the digital transmitter 104 with respect tothree-phase fluid flow through a pipe 2202. In the implementation shownin FIG. 5B, the three-phase fluid flows upward through the Coriolisflowmeter 104.

FIG. 6 is a diagram of another implementation of the system 500 of FIG.5A. In this implementation, the liquid fraction probe 230 is in serieswith the flowtube 215, and fluid flows downward through the flowtube 215and the liquid fraction probe 230. The fluid may be a three-phase fluid,such as a fluid that includes two liquid phases, such as a water phaseand an oil phase, and a gas phase. The system 600 includes an inlet 602though which fluid flows into a pipe 604, the liquid fraction probe 230,the flowtube 215, and an outlet 608 though which fluid flows out of thepipe 604. The system 600 also includes an interface module 609, whichmay include an electronic processor, an electronic storage (such as amemory), and one or more input/output modules (such as a display, acommunications interface for connection to a transmitter incommunication with the flowtube 215 (such as the transmitter 104) and/orconnection with the liquid fraction probe 230, and/or for connection toa remote terminal (not shown), and a tactile manual input, such as akeyboard and a mouse).

The liquid fraction probe 230 may be a watercut meter (or watercutprobe) that measures and provides an estimate of the fraction of waterin the fluid that flows through the water cut meter. The fraction ofwater may be referred to as the water cut. In the system 600, theflowtube 215 is placed such that the fluid flows through the Coriolisflowmeter in a downward direction that corresponds to the direction ofgravity.

In some applications, such as mature oil and gas wells in which thefluid that flows in the pipe 604 has a relatively low pressure and arelatively high gas void fraction (GVF), the fluid may pass through theCoriolis flowmeter as a series of slugs that include mostly gas (andthus have a high GVF) or mostly liquid (and thus have a low GVF). Insome applications, such as monitoring the output of wells in depleted orlow pressure oil and gas reservoirs, the multi-phase stream to bemeasured may include a low pressure stream with high GVF. In theseconditions, better measurement performance may be obtained from themultiphase measurement system if the three-phase mixture passes thoughin a series of slugs of either very high GVF and made almost entirely ofgas or relatively low GVF and made almost entirely of liquid.

Accordingly, an arrangement of the Coriolis flowmeter and the water cutprobe, such as that shown in FIG. 6, may be employed to facilitate slugflow. As compared to a substantially steady fluid stream of separatedliquid with an intermediate GVF, a fluid stream that includes liquid orgas slugs may be more efficiently measured with a Coriolis flowmeter.When a slug of pure, or substantially pure liquid (for example, the slugincludes 95% or more of liquid, passes through the liquid fraction probe230 and the flowtube 215, there may be redundant information. Forexample, when a liquid slug passes through the flowtube 215, measurementdata to resolve three phases (such as gas, oil, and water) may beobtained by the Coriolis flowmeter and watercut meter, but only twophases (such as water and oil) are present. Alternative calculationmethods for the water and oil flow rates may be used for this condition,and the redundant measurement information may be used to providecross-checking between the Coriolis flowmeter and the liquid fractionprobe 230, as described below in FIGS. 7 and 8. Such cross-checking mayprovide an indication of a malfunction or other problem with theCoriolis flowmeter or the liquid fraction probe 230.

The system 600, which may be referred to as the skid 600, may be used inlow pressure, low liquid flow applications, such as a mature oil and gaswells. In the example shown in FIG. 6, the liquid fraction probe 230 andthe flowtube 215 are in a downward orientation on a downward leg 608 ofthe skid 600. Placement of the liquid fraction probe 230 and theflowtube 215 in a downward orientation may be beneficial in lowpressure, high GVF applications. For example, as compared to a system inwhich the Coriolis flowmeter is oriented such that fluid flows in theupward direction through the flowtube 215, positioning the flowtube 215such that fluid flows downward through the flowtube 215 may result inthe Coriolis flowmeter draining more effectively because gravity and anygas flow work in the same direction. Additionally, separation of gas andliquid phases of the multi-phase fluid may occur naturally on the upwardleg 610 of the skid 600 because gas passes through the flowtube 215 atany time, whereas liquid tends to collect in the upward leg 610 until asufficiently large slug of liquid is capable of passing through a topsection 611 of the skid 600 to the downward leg 608. Once the liquid haspassed through the flowtube 215, gravity acts to minimize, or eliminate,liquid flow back into the flowtube 215. In some implementations, adevice to further minimize backwash into the flowtube 215, such as anon-return valve (not shown), may be included in the skid 600. Thus, thearrangement shown in FIG. 6 may encourage slug flow.

Additionally, an arrangement such as shown in FIG. 6 may reduce thepossibility of the flowtube 215 being in a partially filled state (orpartially filled condition). For example, when liquid flow completely ornearly stops, as may occur for extended periods of time for alow-producing oil and gas well, unless the flowtube 215 drainscompletely, the flowtube 215 may enter a partially filled state. Whilein a partially filled state, the flowtube 215 may produce a spurious (ininaccurate), non-zero mass flow reading, which in turn may lead to falsereadings of oil and water flows through the flowtube 215. A partiallyfilled state may be detected independently of detecting the absence offluid flow. For example, a partially filled state may be detected usinga density cutoff such that if the density reported by the transmitter104 is below the density cutoff, the liquid flowrates provided by thetransmitter 104 are set to zero. The cutoff may be, for example, 100kg/m³. In some implementations, another measurement, such as ameasurement from a differential pressure meter, may be used to detectthe presence of liquid flow. A sufficiently high differential pressureacross a section of the skid 600 (such as the pressure across theflowtube 215, across the entire skid 600, or an across anothercomponent, such as an orifice plate in the skid) may indicate thepresence of fluid flow. In some implementations, a flow switch (notshown) may be used to detect the presence or absence of liquid flow.However, the arrangement shown in FIG. 6 reduces or eliminates thepossibility of liquid being trapped within the flowtube 215, thusreducing or eliminating the occurrence of a partially filled state andthe effects of a partially filled state. Moreover, in at least someinstances, the arrangement of the flowtube 215 on the downward leg 608encourages slug flow, and as discussed above, measurements based on slugflow may be more accurate than measurements based on an equivalentnon-slug flow. In some implementations, the liquid fraction probe 230(which may be a water cut meter) may be able to detect that no liquid isin the liquid fraction probe 230. Such an indicator from the liquidfraction probe 230 (which may be a water cut meter) may be used as aflag or indicator to cut off or ignore spurious flow readings from theCoriolis flowmeter.

FIG. 7 shows an example process 700 that may be used to cross-check aCoriolis flowmeter and a water cut probe. The process 700 may beperformed using data from the system 600, however, this is notnecessarily the case. The process 700 may be performed by thetransmitter 104, or the process 700 may be performed by a processor(such as a processor in a flow computer) that is external to, but incommunication with, the transmitter 104. In some implementations, someportions of the process 700 may be performed by the transmitter 104 andsome portions may be performed by a processor that is external to thetransmitter 104. The processor that is external to the transmitter 104may be a processor included in the interface module 609.

The process 700 uses redundancies in measurements produced by thetransmitter 104 and the liquid fraction probe 230 that exist when thefluid that passes through the flowtube 215 and the liquid fraction probe230 is a pure, or substantially pure, liquid. For example, the fluid maybe substantially pure when the fluid includes more than 95% liquid. Thefluid may be purely liquid when liquid slugs that include, for example,an oil phase and a water phase, but not a gas phase, flow through theliquid fraction probe 230 and the flowtube 215. When a slug of pureliquid passes through the liquid fraction probe 230 and the flowtube215, and measurement data to resolve three phases (oil, gas, water) isavailable but only two phases (oil, water) are present, each of theflowmeter 104 and the liquid fraction probe 230 may produce redundantinformation that may be used to cross-check the data obtained from thetransmitter 104 with that obtained from the liquid fraction probe 230.Cross-checking the Coriolis flowmeter with, for example, a water cutprobe may be used to identify a malfunction in either or both of theCoriolis flowmeter and the water cut probe and/or to identify anincorrect assumption in a preset or preconfigured system parameter, suchas an assumed water or oil density.

Referring to FIG. 7, a multi-phase fluid is passed through the flowtube215 (705), and the multi-phase fluid is passed through the liquidfraction probe 230 (710). The multi-phase fluid includes two phasesduring a first time period and three phases during a second time period.For example, the multi-phase fluid may include an oil phase and a waterphase during the first time period, and an oil phase, a water phase, anda gas phase during a second time period. Thus, during the first timeperiod, the multi-phase fluid may considered to be a liquid, or nearlyliquid, slug and may be considered to be free of gas and to have a verylow GVF (for example, a GVF lower than 5%). In some implementations, thefirst time period is long enough to provide for multiple measurements tobe obtained from the liquid fraction probe 230 and the transmitter 104.For example, the first time period may be of a duration that correspondsto ten measurements or ten measurement updates. A measurement may occur,for example, approximately every second. Thus, the first time period maybe a time that is about ten seconds or greater. As discussed in below,in some implementations, the measurements from the transmitter 104 andthe liquid fraction probe 230 taken during a time period may be filteredto reduce noise and improve accuracy and performance, thus, multiplemeasurements taken during the first time period may improve accuracy.

It is determined that the multi-phase fluid includes two phases duringthe first time period (715). In some examples, the two phases may be oiland water, thus the multi-phase fluid is substantially free of gas. Themulti-phase fluid may be deemed to be free of gas when a low drive gainreading is obtained from the Coriolis flowmeter. For example, a drivegain of 0.05 or less may be considered to be a low drive gain thatindicates that the multi-phase fluid is free gas. A low drive gain isindicative of a flow that includes only liquid or only gas.Additionally, or alternatively, a density reading from the transmitter104 may provide an indication as to whether a low drive gain may beattributed to the presence of a pure liquid. For example, a densityreading of greater than about 700 kg/m³ strongly indicates that thefluid is a pure liquid, whereas a density reading less than about 100kg/m³ indicates that the fluid is a pure gas, depending on the pressureconditions at the point of density measurement.

A first value of a parameter of the multi-phase fluid is determinedusing information from the transmitter 104 (720), and a second value ofthe parameter of the multi-phase fluid is determined using informationfrom the liquid fraction probe 230 (725). The parameter may be, forexample, a liquid density or a watercut (e.g., a fraction or percentageof the flow that is water). The first value of the parameter is comparedto the second value of the parameter (730). Based on the comparison, itis determined whether the first value of the parameter and the secondvalue of the parameter are inconsistent with each other (735). Asdiscussed in greater detail below, inconsistencies between the firstvalue of the parameter and the second value of the parameter indicatethat either the Coriolis transmitter 104 or the liquid fraction probe230 are malfunctioning or that certain assumed and preconfigured values,such as liquid density or oil density, are inaccurate.

In greater detail, in some circumstances where the drive gain, densityand perhaps other signals indicate a pure liquid mixture, there may beredundancy between the readings provided by the Coriolis flowmeter (suchas the transmitter 104 that is coupled to the flowtube 215) and a watercut meter (such as the liquid fraction probe 230). For example, with no,or very little, gas in the flow stream, an estimate of the water cutbased upon Coriolis flowmeter readings only, δ_(wC) may be determined asfollows:

$\begin{matrix}{\delta_{wC} = {\frac{\left( {\rho_{m} - \rho_{o}} \right)}{\left( {\rho_{w} - \rho_{o}} \right)} \times 100\%}} & {{Eq}.\mspace{14mu} 10}\end{matrix}$

In Equation 10, ρ_(o) is the oil density (assumed known), ρ_(w) is thewater density (assumed known), and ρ_(m) as the mixture density measuredby the Coriolis flowmeter. The estimate of the watercut based on theCoriolis flowmeter readings may be compared against the reading obtainedfrom the water cut meter δ_(mW) (also as a percentage). Instances wherea significant difference (such as, for example 5%) may be indicative ofan inconsistency.

In some implementations, an estimated liquid density is calculated basedon the readings from the water cut, using

$\begin{matrix}{{\rho_{mW} = {{\frac{\delta_{wW}}{100}*\rho_{w}} + {\left( {1 - \frac{\delta_{wW}}{100}} \right)*\rho_{o}}}},} & {{Eq}.\mspace{14mu} 11}\end{matrix}$

The Coriolis flowmeter density reading of the mixture (e.g., thetwo-phase liquid slug) ρ_(m) may be compared with the density estimatefrom Equation 11 based on the water cut reading. (ρ_(mW)).

Regardless of the parameter that is compared, a significant differencebetween the values obtained using the water cut meter and the valuesobtained using the Coriolis flowmeter readings may indicate aninaccuracy in the assumed value of ρ_(o) or the assumed value of ρ_(w)or may indicate a malfunction of the Coriolis flowmeter or the water cutmeter. The amount of difference needed to indicate such an inaccuracy ormalfunction may be determined, for example, experimentally.

In some implementations, further information may be used to determinewhich component is contributing to the inconsistency between the valueof a parameter (such as density or water cut) determined using data fromthe Coriolis flowmeter and the value of the parameter determined usingdata from the water cut meter. For example, in applications where waxingor sand damage of the water cut meter is possible, the water cut metermay be considered the most likely source of the inconsistency. Inanother example, if the Coriolis flowmeter produces a density readingthat is higher than the water density, particularly if a reading fromthe water cut meter indicates a nearly 100% portion of water, theassumed water density (ρ_(w)) is likely inaccurate. The assumed waterdensity may be inaccurate when, for example, the salinity of the waterin the multi-phase fluid changes unexpectedly. Similarly, if theCoriolis flowmeter reads a density that is lower than the oil density(particularly if this is reinforced by a near 0% reading from the watercut meter, indicating that the flow is nearly free of water), andassuming there is particularly strong evidence against the presence ofgas, this suggests that the assumed oil density ρ_(o) is not accurate.

Such a set of readings may trigger an alarm and/or a request toreconfigure, respectively, the assumed water density or the assumed oildensity. In some implementations, the presence of readings indicating aninaccurate assumed or pre-configured water or oil density may trigger orcause an automatic adjustment of the assumed or pre-configured water oroil density. Additionally, the water cut meter is unlikely to generatemeasurements outside of the range of 0 to 100%, whereas theCoriolis-based calculation of water cut may fall below 0% or exceed 100%as a consequence of an inaccurate pre-configured density for water oroil. Accordingly, where the Coriolis flowmeter generates a water cutreading outside the range of 0 to 100%, comparison with the water cutmeter may be bypassed. Thus, the presence of an inconsistency between avalue of a parameter (such as density or watercut) determined based ondata from the transmitter 104 and a value of the same parameterdetermined based on data from the liquid fraction probe 230, mayindicate equipment malfunction or inaccuracy in certain assumedparameters.

The techniques discussed above may be employed during liquid-onlyconditions, which may occur sporadically during operation of a systemsuch as the skid 600. To help mitigate against false detections of aninconsistency stemming from transient effects (such as a sudden andshort-lived increase in the liquid in the multi-phase flow) rather thanactual liquid-only conditions, the data used to determine whether aninconsistency exists may be tracked over time and filtered to removetransient effects. For example, the data collected from the transmitter104 and the liquid fraction probe 230 may be updated at a measurementrate of, for example, 1 second. Accordingly, for a time period of, forexample, 100 seconds, the data from the transmitter 104 and the liquidfraction probe 230, would form a time-series of 100 points (assumingthat each measurement update was successfully completed). Because thetime-series of data from the transmitter 104 and the liquid fractionprobe 230 may be irregular due to transient effects, the time-series maybe filtered by, for example, determining the mean (average) value of thetime-series, determining the standard deviation of the time-series,and/or by determining the maximum and minimum value of the time-series.Determining the mean value of the time-series may remove spike valuesand ensure that decisions are based on data taken over a sufficientlylong period of time. The standard deviation of a time-series of, forexample, the difference between the Coriolis and watercut readings mayshow how much the difference varies over time. The minimum and maximumvalues may be used to diagnose inaccuracies with the assumed pure fluiddensities.

FIG. 8 shows another example process for determining whether aninconsistency between a density measured with the Coriolis flowmeter anda density determined using readings from the water cut meter isattributable to a malfunction in a water cut probe or a Coriolisflowmeter. The process 800 may be performed on a system such as thesystem 600. The process 800 may be performed by the transmitter 104, orthe process 800 may be performed by a processor (such as a processor ina flow computer) that is external to the flowtube 215 and the liquidfraction probe 230 but in communication with the transmitter 104. Insome implementations, some portions of the process 800 may be performedby the transmitter 104 and some portions may be performed by theprocessor that is external to the transmitter 104. The processor that isexternal to, but in communication with, the transmitter may be aprocessor included in the interface module 609.

A measurement update is initiated (805). Values are read from the watercut meter (810) and values are read from the Coriolis flowmeter (815).Values read from the water cut meter include a water cut reading(watercut_W) that represents a measurement of a percentage of themulti-phase fluid that is water. Values read from the Coriolis flowmeterinclude a density of the multi-phase fluid (dens_mix), a massflow(massflow_mix) of the multi-phase fluid, and a drive gain (drive_gain).If available, values of the pressure and temperature of the multi-phasefluid may also be read. The pure oil density (dens_o) is determined forcurrent pressure and temperature conditions, and the pure water density(dens_w) is determined for current pressure and temperature conditions(820). The pure oil density (dens_o) and pure water density (dens_w) maybe referred to as assumed or configured densities. In someimplementations, rather than determine the pure oil density and purewater density from current pressure and temperature conditions, thesedensities are preset and stored, for example, in the processinginterface 630.

Whether gas is present in the multi-phase fluid is determined (825). Thepresence of gas may be determined, for example, based on the drive gainobtained from the Coriolis flowmeter. If gas is present, the process 800ends and the three-phase measurements discussed above with respect toFIG. 5 may be performed. If gas is not present, the density of themulti-phase fluid (dens_mix) read from the Coriolis flowmeter isanalyzed (830). The density of the multi-phase fluid is compared to apreset threshold that is selected to indicate whether or not the densityof the multi-phase fluid indicates that the multi-phase fluid is purelygas. For example, the threshold may be 750 kg/m³, and if the density ofthe multi-phase fluid is less than the threshold, the multi-phase fluidis deemed to be not purely liquid and the process 800 ends. Otherwise,the density of the fluid is greater than or equal to the threshold andis assumed to be purely liquid. The density of the multi-phase fluid iscompared to the configured density of pure oil (dens_o). If the value ofthe observed density is less than the configured oil density, then thevalue of the observed density may be reported, presented and/or storedin an electronic storage medium, and the process 800 ends. In someimplementations, an alarm is set to indicate that the configured densityof pure oil may be incorrect. If the value of the observed density isgreater than the configured oil density, the process 800 continues, andthe value of the observed density is compared to the configured waterdensity (dens_w). If the value of the observed density is greater thanthe configured water density, the observed density may be recorded,presented, and/or stored, and the process 800 ends. In someimplementations, an alarm may be set to indicate that the configuredwater density may be incorrect. If the process 800 has not ended, thevalue of the observed density is between the configured oil density andthe configured water density, and an estimate of the water cut may bereliably obtained.

A counter (time_gf) is incremented (835). Incrementing the counterindicates that another measurement of the multi-phase fluid without gashas occurred. The counter provides an indication of the amount of timedata has been collected with a gas-free multi-phase fluid passingthrough the Coriolis flowmeter and the water cut meter. If sufficienttime has passed (and, thus, sufficient gas-free measurements have beentaken), a density value is determined based on the water cut readingfrom the water cut meter (840). In some implementations, 100measurements may be the minimum number of measurements, in otherimplementations a minimum of 10 measurements may be the threshold. Thedensity value determined based on the water cut reading is compared tothe density value obtained from the Coriolis flowmeter (845). Thecomparison may be done for each measurement corresponding to anincrement of the counter, and the comparison may be a percentagedifference between the density observed by the Coriolis flowmeter andthe density determined based on the readings from the water cut meter.The mean and standard deviation of the percentage difference may bedetermined (850).

Whether difference between the density observed by the Coriolisflowmeter and the density determined using readings from the water cutmeter is attributable to a malfunction in the water cut meter or theCoriolis flowmeter is determined (855). In some implementations, theabsolute value of the average difference between the two densities beinggreater then a threshold is an indication that water cut probe isexperiencing an error. The threshold may be, for example, about 4%. Insome implementations, if the standard deviation of the differencebetween the densities is greater than a threshold of, for example, 3%,an error may exist in the water cut probe.

Other implementations are within the scope of the claims.

1. A method comprising: passing a multi-phase fluid through a Coriolisflowmeter, the multi-phase fluid comprising two phases during a firsttime period and three phases during a second time period; passing themulti-phase fluid through a watercut meter; determining that themulti-phase fluid includes two phases during the first time period;determining a first value of a parameter of the multi-phase fluid usinga value measured by the Coriolis flowmeter during the first time period;determining a second value of a parameter of the multi-phase fluid usinga value measured by the watercut meter during the first time period;comparing the first value to the second value; and determining, based onthe comparison, that the first value and the second value areinconsistent with each other.
 2. The method of claim 1, wherein theparameter comprises density of the multi-phase fluid, and the firstvalue is a first density value and the second value is a second densityvalue.
 3. The method of claim 1, wherein the parameter comprises a watercut of the multi-phase fluid, and the first value is a water cutmeasured by the water cut meter, and the second value is a water cutdetermined using values read from the Coriolis flowmeter.
 4. The methodof claim 2, wherein comparing the first density value to the seconddensity value comprises determining a percentage difference between thefirst density value and the second density value.
 5. The method of claim1, further comprising determining, based on the inconsistency, that anerror exists in the watercut meter.
 6. The method of claim 1, furthercomprising determining, based on the inconsistency, that an error existsin the Coriolis flowmeter.
 7. The method of claim 2, wherein the seconddensity is determined using${\rho_{mW} = {{\frac{\delta_{wW}}{100}*\rho_{w}} + {\left( {1 - \frac{\delta_{wW}}{100}} \right)*\rho_{o}}}},$where ρ_(o) is an assumed oil density, ρ_(w) is an assumed waterdensity,$\delta_{wC} = {\frac{\left( {\rho_{m} - \rho_{o}} \right)}{\left( {\rho_{w} - \rho_{o}} \right)} \times 100\%}$is an estimate of the watercut, and ρ_(m) is the first density of themulti-phase fluid measured by the Coriolis flowmeter.
 8. The method ofclaim 1, wherein the multi-phase fluid during the first time period ispurely liquid.
 9. The method of claim 1, wherein determining, based onthe comparison, that the first value and the second value areinconsistent with each other comprises determining that a percentagedifference between the first value and the second value exceeds athreshold.
 10. The method of claim 9, wherein the threshold is about 5%.11. A system comprising: a watercut meter configured to receive a fluid;and a Coriolis flowmeter coupled to the watercut meter, wherein theCoriolis flowmeter is configured to receive the fluid, and the flowmeteris oriented such that the fluid flows downward through the Coriolisflowmeter, further comprising a computing device configured to:determine that the multi-phase fluid includes two phases during thefirst time period; determine a first value of a parameter of themulti-phase fluid using a value measured by the Coriolis flowmeterduring the first time period; determine a second value of a parameter ofthe multi-phase fluid using a value measured by the watercut meterduring the first time period; compare the first value to the secondvalue; and determine, based on the comparison, that the first value andthe second value are inconsistent with each other.
 12. The system ofclaim 11, wherein the parameter comprises density of the multi-phasefluid, and the first value is a first density value and the second valueis a second density value.
 13. The system of claim 11, wherein theparameter comprises a water cut of the multi-phase fluid, and the firstvalue is a water cut measured by the water cut meter, and the secondvalue is a water cut determined using values read from the Coriolisflowmeter.
 14. The system of claim 12, wherein to compare the firstdensity value to the second density value, the computing device isconfigured to determine a percentage difference between the firstdensity value and the second density value.
 15. The system of claim 11,further comprising determining, based on the inconsistency, that anerror exists in the watercut meter.
 16. The system of claim 11, whereinthe computing device is further configured to determine, based on theinconsistency, that an error exists in the Coriolis flowmeter.
 17. Thesystem of claim 12, wherein the second density is determined using${\rho_{mW} = {{\frac{\delta_{wW}}{100}*\rho_{w}} + {\left( {1 - \frac{\delta_{wW}}{100}} \right)*\rho_{o}}}},$where ρ_(o) is an assumed oil density, ρ_(w) is an assumed waterdensity,$\delta_{wC} = {\frac{\left( {\rho_{m} - \rho_{o}} \right)}{\left( {\rho_{w} - \rho_{o}} \right)} \times 100\%}$is an estimate of the watercut, and ρ_(m) is the first density of themulti-phase fluid measured by the Coriolis flowmeter.
 18. The system ofclaim 11, wherein the computing device is further configured todetermine, based on the inconsistency, that at least one of the assumedoil density or the assumed water density is inaccurate.
 19. The systemof claim 12, wherein the watercut meter comprises a liquid fractionprobe.
 20. A system comprising: a watercut meter configured to receive afluid; and a Coriolis flowmeter coupled to the watercut meter, whereinthe Coriolis flowmeter is configured to receive the fluid, and theflowmeter is oriented such that the fluid flows downward through theCoriolis flowmeter.